Recovery From A Hydrocarbon Reservoir

ABSTRACT

Embodiments described herein provide systems and methods for improving production of hydrocarbon resources. A method for improving recovery from a subsurface hydrocarbon reservoir includes drilling a well comprising a horizontal segment through a reservoir interval and installing a pipe string in the horizontal well segment, wherein the pipe string comprises a plurality of screen assemblies. Each of the plurality of screen assemblies is located and a hole is drilled in the pipe string at a portion of the plurality of screen assemblies. Each hole is drilled at a desired orientation to a radial axis of the drill string.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of Canadian Patent Application 2,762,439 filed Dec. 16, 2011 entitled IMPROVING RECOVERY FROM A HYDROCARBON RESERVOIR, the entirety of which is incorporated by reference herein.

FIELD

The present techniques relate to harvesting resources using gravity drainage processes. Specifically, techniques are disclosed for placing holes in the bottom of wells within a reservoir.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

Modern society is greatly dependant on the use of hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface rock formations that can be termed “reservoirs.” Removing hydrocarbons from the reservoirs depends on numerous physical properties of the rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the rock formations, and the proportion of hydrocarbons present, among others.

Easily harvested sources of hydrocarbon are dwindling, leaving less accessible sources to satisfy future energy needs. However, as the costs of hydrocarbons increase, these less accessible sources become more economically attractive. For example, the harvesting of oil sands to remove hydrocarbons has become more extensive as it has become more economical. The hydrocarbons harvested from these reservoirs may have relatively high viscosities, for example, ranging from 8 API, or lower, up to 20 API, or higher. Accordingly, the hydrocarbons may include heavy oils, bitumen, or other carbonaceous materials, collectively referred to herein as “heavy oil,” which are difficult to recover using standard techniques.

Several methods have been developed to remove hydrocarbons from oil sands. For example, strip or surface mining may be performed to access the oil sands, which can then be treated with hot water or steam to extract the oil. However, deeper formations may not be accessible using a strip mining approach. For these formations, a well can be drilled to the reservoir and steam, hot air, solvents, or combinations thereof, can be injected to release the hydrocarbons. The released hydrocarbons may then be collected by the injection well or by other wells and brought to the surface.

A number of techniques have been developed for harvesting heavy oil from subsurface formations using thermal recovery techniques. Thermal recovery operations are used around the world to recover liquid hydrocarbons from both sandstone and carbonate reservoirs. These operations include a suite of steam based in situ thermal recovery techniques, such as cyclic steam stimulation (CSS), steam flooding, and steam assisted gravity drainage (SAGD).

For example, CSS techniques includes a number of enhanced recovery methods for harvesting heavy oil from formations that use steam heat to lower the viscosity of the heavy oil. The steam is injected into the reservoir through a well and raises the temperature of the heavy oil during a heat soak phase, lowering the viscosity of the heavy oil. The same well may then be used to produce heavy oil from the formation. CSS is generally practiced in vertical wells, but systems are operational in horizontal wells. CSS and other steam flood techniques have been utilized worldwide, beginning in about 1956 with the utilization of CSS in the Mene Grande field in Venezuela and steam flood in the early 1960s in the Kern River field in California.

Solvents may be used in combination with steam in CSS processes, such as in mixtures with the steam or in alternate injections between steam injections. These techniques are described in U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to McMillen, and U.S. Pat. No. 4,697,642 to Vogel, among others.

Another group of techniques is based on a continuous injection of steam through a first well to lower the viscosity of heavy oils and a continuous production of the heavy oil from a lower-lying second well. Such techniques may be termed “steam assisted gravity drainage” or SAGD. Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 to Butler and its corresponding U.S. Pat. No. 4,344,485.

In SAGD, two horizontal wells are completed into the reservoir. The two wells are first drilled vertically to different depths within the reservoir. Thereafter, using directional drilling technology, the two wells are extended in the horizontal direction that result in two horizontal wells, vertically spaced from, but otherwise vertically aligned with the other. Ideally, the production well is located above the base of the reservoir but as close as practical to the bottom of the reservoir, and the injection well is located vertically 10 to 30 feet (3 to 10 meters) above the horizontal well used for production.

Each of the wellbores is assembled from pipe segments, for example, of about 30 feet in length. Each pipe segment has exterior threads at one end and interior threads at the opposite end that couple the segments together. Variations in the threading can result in slight variations of the orientation of each segment to the next segment in the string.

The upper horizontal well is utilized as an injection well and is supplied with steam from the surface. The steam rises from the injection well, permeating the reservoir to form a vapor chamber that grows over time towards the top of the reservoir, thereby increasing the temperature within the reservoir. The steam, and its condensate, raise the temperature of the reservoir and consequently reduce the viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam will then drain downward through the reservoir under the action of gravity and may flow into the lower production well, whereby these liquids can be pumped to the surface. At the surface of the well, the condensed steam and heavy oil are separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transport by pipeline.

Solvents may be used alone or in combination with steam addition to increase the efficiency of the steam in removing the heavy oils. As the solvents blend with the heavy oils and bitumens, they lower the viscosity, allowing the materials to flow towards a production well. The mobility of the heavy oil obtained with the steam and solvent combination is greater than that obtained using steam alone under substantially similar formation conditions.

The techniques discussed above may have uneven or even limited injection of steam into the reservoir, for example, due to the random orientation of the pipe segments to each other in the reservoir. Further, conventional slotted liners, meshrite, and wirewrap screen assemblies have openings that allow fluids to flow into the liner from 360 degrees. With these liners in SAGD, steam coning will occur when the steam chamber is proximal to top of the liners. This can lead to lower efficiency for steam injection as well as early steam breakthrough.

SUMMARY

Some embodiments of the present invention provide variations of method for improving recovery from a subsurface hydrocarbon reservoir. The method includes drilling a well with a horizontal segment through a reservoir interval, installing a pipe string having a plurality of screen assemblies in the horizontal well segment, locating each of the plurality of screen assemblies, and drilling a hole in the pipe string at a portion of the plurality of screen assemblies, wherein each hole is drilled at a desired orientation to a radial axis of the drill string.

Other embodiments of the invention include variations of a system for improving the recovery of resources from a reservoir. The system includes a reservoir, a horizontal well drilled through the reservoir, wherein the horizontal well comprises a plurality of pipe joints that have a screen assembly mounted thereon; a detection apparatus configured to locate a screen assembly on a pipe joint; and a drilling device configured to drill a hole in a pipe joint at a selected orientation to the vertical.

Yet other embodiments of the invention include variations of a method for harvesting hydrocarbons from an oil sands reservoir. The method includes: drilling a steam assisted gravity drainage (SAGD) well pair through the oil sands reservoir; placing a pipe string in each of the wells of the SAGD well pair, wherein the pipe string comprises a plurality of screen assemblies, and wherein the pipe string has no holes prior to placement; selecting a portion of the screen assemblies at which to drill holes in a base pipe underneath the screen assembly; drilling the holes at a selected orientation to the radial axis of the base pipe; injecting steam into an injection well in the SAGD well pair; and producing fluids from a production well in the SAGD well pair.

DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood by referring to the following detailed description and the attached drawings, in which:

FIG. 1 is a drawing of a steam assisted gravity drainage (SAGD) process used for harvesting hydrocarbons in a reservoir;

FIG. 2 is a drawing of a screen assembly, showing a location of a hole;

FIG. 3 is a cross section of a blast joint section of the screen assembly of FIG. 2;

FIG. 4 is a cross section of a wirewrap screen section of the screen assembly of FIG. 2;

FIG. 5 is a drawing of a pipe segment that includes a wirewrap screen;

FIG. 6 is a drawing of a pipe segment, showing a build-up in condensate due to non-vertical hole locations;

FIG. 7 is a drawing of a pipe segment, showing complete drainage of condensate when the holes are located at the bottom of a segment;

FIG. 8 is a plot showing the use of gamma ray logging to locate blast joints to allow the positioning of holes;

FIG. 9(A) is a drawing of a series of screen assemblies placed on a pipe segment;

FIG. 9(B) is a drawing of a series of screen assemblies placed on a pipe segment;

FIG. 9(C) is a drawing of a series of screen assemblies placed on a pipe segment; and

FIG. 10 is a method of improving the harvesting of hydrocarbons from a reservoir by drillings holes after the well is lined.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments of the present techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

As used herein, the term “base” indicates a lower boundary of the resources in a reservoir that are practically recoverable, by a gravity-assisted drainage technique, for example, using an injected mobilizing fluid, such as steam, solvents, hot water, gas, and the like. The base may be considered a lower boundary of the payzone. The lower boundary may be an impermeable rock layer, including, for example, granite, limestone, sandstone, shale, and the like. The lower boundary may also include layers that, while not completely impermeable, impede the formation of fluid communication between a well on one side and a well on the other side.

“Bitumen” is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:

19 wt. % aliphatics (which can range from 5 wt. %-30 wt. %, or higher);

19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %, or higher);

30 wt. % aromatics (which can range from 15 wt. %-50 wt. %, or higher);

32 wt. % resins (which can range from 15 wt. %-50 wt. %, or higher); and

some amount of sulfur (which can range in excess of 7 wt. %).

In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon types found in bitumen can vary. As used herein, the term “heavy oil” includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir.

As used herein, two locations in a reservoir are in “fluid communication” when a path for fluid flow exists between the locations. For example, the establish of fluid communication between a lower-lying serpentine well and a higher injection well may allow material mobilized from a steam chamber above the injection well to flow down to the serpentine well from collection and production. As used herein, a fluid includes a gas or a liquid and may include, for example, a produced hydrocarbon, an injected mobilizing fluid, or water, among other materials.

As used herein, a “cyclic recovery process” uses an intermittent injection of injected mobilizing fluid selected to lower the viscosity of heavy oil in a hydrocarbon reservoir. The injected mobilizing fluid may include steam, solvents, gas, water, or any combinations thereof. After a soak period, intended to allow the injected material to interact with the heavy oil in the reservoir, the material in the reservoir, including the mobilized heavy oil and some portion of the mobilizing agent may be harvested from the reservoir. Cyclic recovery processes use multiple recovery mechanisms, in addition to gravity drainage, early in the life of the process. The significance of these additional recovery mechanisms, for example dilation and compaction, solution gas drive, water flashing, and the like, declines as the recovery process matures. Practically speaking, gravity drainage is the dominant recovery mechanism in all mature thermal, thermal-solvent and solvent based recovery processes used to develop heavy oil and bitumen deposits, such as steam assisted gravity drainage (SAGD). For this reason the approaches disclosed here are equally applicable to all recovery processes in which at the current stage of depletion gravity drainage is the dominant recovery mechanism.

“Facility” as used in this description is a tangible piece of physical equipment through which hydrocarbon fluids are either produced from a reservoir or injected into a reservoir, or equipment which can be used to control production or completion operations. In its broadest sense, the term facility is applied to any equipment that may be present along the flow path between a reservoir and its delivery outlets. Facilities may comprise production wells, injection wells, well tubulars, wellhead equipment, gathering lines, manifolds, pumps, compressors, separators, surface flow lines, steam generation plants, processing plants, and delivery outlets. In some instances, the term “surface facility” is used to distinguish those facilities other than wells.

“Heavy oil” includes oils which are classified by the American Petroleum Institute (API), as heavy oils, extra heavy oils, or bitumens. In general, a heavy oil has an API gravity between 22.3° (density of 920 kg/m³ or 0.920 g/cm³) and 10.0° (density of 1,000 kg/m³ or 1 g/cm³). An extra heavy oil, in general, has an API gravity of less than 10.0° (density greater than 1,000 kg/m³ or greater than 1 g/cm³). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water, and bitumen. The thermal recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluids by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.

A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, hydrocarbons generally refer to components found in heavy oil, or other oil sands.

As used herein, “poorer quality facies” are intervals in a reservoir that can have poor drainage, often due to a difficulty in establishing a counter-current flow. In an oil sands reservoir, poorer quality facies may include IHS layers above the higher quality sands of a clean pay interval.

“Permeability” is the capacity of a rock to transmit fluids through the interconnected pore spaces of the rock. The customary unit of measurement for permeability is the millidarcy. The term “relatively permeable” is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy). The term “relatively low permeability” is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy.

“Pressure” is the force exerted per unit area by the gas on the walls of the volume. Pressure can be shown as pounds per square inch (psi). “Atmospheric pressure” refers to the local pressure of the air. “Absolute pressure” (psia) refers to the sum of the atmospheric pressure (14.7 psia at standard conditions) plus the gauge pressure (psig). “Gauge pressure” (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia). The term “vapor pressure” has the usual thermodynamic meaning. For a pure component in an enclosed system at a given pressure, the component vapor pressure is essentially equal to the total pressure in the system.

As used herein, a “reservoir” is a subsurface rock or sand formation from which a production fluid, or resource, can be harvested. The rock formation may include sand, granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy oil, oil, gas, or coal, among others. Reservoirs can vary in thickness from less than one foot (0.3048 m) to hundreds of feet (hundreds of m). The resource is generally a hydrocarbon, such as a heavy oil impregnated into a sand bed.

As discussed in detail above, “Steam Assisted Gravity Drainage” (SAGD), is a thermal recovery process in which steam, or combinations of steam and solvents, is injected into a first well to lower a viscosity of a heavy oil, and fluids are recovered from a second well. Both wells are generally horizontal in the formation and the first well lies above the second well. Accordingly, the reduced viscosity heavy oil flows down to the second well under the force of gravity, although pressure differential may provide some driving force in various applications. Although SAGD is used as an exemplary process herein, it can be understood that the techniques described can include any gravity driven process, such as those based on steam, solvents, or any combinations thereof.

“Substantial” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.

As used herein, “thermal recovery processes” include any type of hydrocarbon recovery process that uses a heat source to enhance the recovery, for example, by lowering the viscosity of a hydrocarbon. These processes may use injected mobilizing fluids, such as hot water, wet steam, dry steam, or solvents alone, or in any combinations, to lower the viscosity of the hydrocarbon. Such processes may include subsurface processes, such as cyclic steam stimulation (CSS), cyclic solvent stimulation, steam flooding, solvent injection, and SAGD, among others, and processes that use surface processing for the recovery, such as sub-surface mining and surface mining. Any of the processes referred to herein, such as SAGD, may be used in concert with solvents.

A “wellbore” is a hole in the subsurface made by drilling or inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.” Further, multiple pipes may be inserted into a single wellbore, for example, as a liner configured to allow flow from an outer chamber to an inner chamber.

Overview

Current throttle-flow liner designs often use screen assemblies on pipe segments, such as wirewrap screens, wirewrap screens with blast joints, and the like, to improve the contact of wellbores with a reservoir. As used herein, a liner is a portion of a well used for recovering resources from a reservoir. The liner may often have a base pipe with attached screen assemblies for allowing fluid flow into and out of the base pipe. Before installation, a limited number of holes may be drilled in the base pipe, behind the screen assemblies, to regulate the flow to or from the reservoir.

In an embodiment, the screen assemblies are located and the holes are drilled after the screen assemblies have been installed in the reservoir. This allows the holes to be positioned at any selected angle to the radial axes of horizontal pipe segments. For example, the holes can be positioned to point downward into the screen assembly. A low position, combined with a “V shape” drainage profile, can reduce the quantity of injectant vapor, such as steam, solvent vapor, or combinations, than may be coned into a production well, e.g., being produced as vapor. By reducing the liquid sump above the depth of the producer, it can also increase the height of the pay interval that is exposed to the injectant vapor, further increasing the production rates and recovery.

For the purposes of this description, SAGD is used as the recovery process. Those ordinarily skilled in the art will recognize that the approaches disclosed here are equally applicable to all thermal, thermal-solvent and solvent based recovery processes in which gravity drainage is the dominant recovery mechanism.

FIG. 1 is a drawing of a steam assisted gravity drainage (SAGD) process 100 used for accessing hydrocarbon resources in a reservoir 102. In the SAGD process 100, steam 104 can be injected through injection wells 106 to the reservoir 102. As previously noted, the injection wells 106 may be horizontally drilled through the reservoir 102. Production wells 108 may be drilled horizontally through the reservoir 102, with a production well 108 underlying each injection well 106. Generally, the injection wells 106 and production wells 108 will be drilled from the same pads 110 at the surface 112. This may make it easier for the production well 108 to track the injection well 106. However, in some embodiments the wells 106 and 108 may be drilled from different pads 110.

The injection of steam 104 into the injection wells 106 may result in the mobilization of hydrocarbons 114, which may drain to the production wells 108 and be removed to the surface 112 in a mixed stream 116 that can contain hydrocarbons, condensate and other materials, such as water, gases, and the like. As described herein, screen assemblies may be used on the injection wells 106, for example, to throttle the inflow of injectant vapor to the reservoir 102. Similarly, screen assemblies may be used on the production wells 108, for example, to decrease sand entrainment.

The hydrocarbons 114 may form a triangular shaped drainage chamber 118 that has the production well 108 at located at a lower apex. The mixed stream 116 from a number of production wells 108 may be combined and sent to a processing facility 120. At the processing facility 120, the water and hydrocarbons 122 can be separated, and the hydrocarbons 122 sent on for further refining. Water from the separation may be recycled to a steam generation unit within the facility 120, with or without further treatment, and used to generate the steam 104 used for the SAGD process 100.

An interval 126 of the reservoir 102 may include poorer quality facies, such as an IHS layer, which drains poorly. The poorer quality facies are not limited to intervals 126 at the top of a reservoir 120, but may include lenses 128 or other places in the reservoir 102. As described herein, cycling the pressure of the reservoir 102 may increase the drainage from the interval 126 and lenses 128, allowing increases in production of hydrocarbons from these locations.

Screen Assemblies

FIG. 2 is a drawing 200 of a screen assembly 202 mounted on a base pipe 204. In this example, a center section of the screen assembly 202 has a blast joint 206, which is joined to wirewrap screens 208 along each outer edge of the blast joint 206. The wirewrap screens 208 are joined to the base pipe 204 by welds 210, for example, to prevent injectant from escaping around the wirewrap screens 208 or sand from infiltrating beneath the wirewrap screens 208. A hole 212 is drilled below the blast joint 206 to allow injectant vapor to escape from injection wellbores or production fluids to enter production wellbores.

A design criterion for conventional liners, such as slotted liners, wirewrap screens, or meshrite screens, is to ensure that sufficient open area is present in the to prevent the liner from being a flow restriction. However, this design approach can make the screens of the liners susceptible to sand influx damage such as erosion or plugging. For example, this may occur if high fluid velocities are present at one or more locations along a wellbore.

FIG. 3 is a cross section of the blast joint 206 of the screen assembly 202 of FIG. 2. The blast joint 206 is a single metal pipe, for example, made from iron or steel. The hole 212 in the base pipe 204 opens behind the blast joint 206. In this example, the hole 212 is oriented along the vertical axis 304 of the base pipe. In an injection well, the injectant, such as steam, is released into the annulus 302 between the blast joint 206 and the base pipe 204. This protects the more fragile wirewrap screens 208 from erosion caused by the influx of injectant vapor. The injectant vapor flows through the annulus 302 to the wirewrap screens 208, as discussed with respect to FIG. 4. Further, the presence of the blast joints 206 directly outside the locations of the holes 212 will deflect the injectant vapor exiting the holes, thereby ensuring that it will not adversely affect the operation of any underlying production well.

FIG. 4 is a cross section of a wirewrap screen 208 of the screen assembly 202 of FIG. 2. For a production well, the injectant vapor that exits the base pipe 204 through the hole 212 into the annulus 302 between the base pipe 204 and the blast joint 206 flows to the annulus 402 between the wirewrap screens 208 and the base pipe 204. From there, the injectant vapor flows into the reservoir through slots in the wirewrap screen 208. Similarly, for a production well, production fluids can flow through the slots in the wirewrap screen 208 into the annulus 402 between the wirewrap screens 208 and the base pipe 204 and then into the annulus 302 between the base pipe 204 and the blast joint 206. The production fluids can then flow into the base pipe 204 of the production well through the hole 212.

The throttled-flow liner design for the screen assembly 202, illustrated in FIGS. 2-4, can improve the robustness of the screen assembly 202 to damage by creating a flow restriction in a base pipe 204, for example, by limiting the number of holes 212. In contrast, previous systems had the flow restriction occur across the wirewrap screen 208. When the throttled flow liner is the screen assembly 202 used for injection wells, the number of screen assemblies 202 and their specific locations along the wellbore are based on the requirements of the specific thermal, thermal-solvent or solvent based recovery process. However, the orientation of the holes 212 for each of the segment a string of pipe is random and, thus, may not be optimal in all services, as discussed with respect to FIG. 5.

FIG. 5 is a drawing of a pipe segment (or joint) 502 that includes a screen assembly 202 and a pre-drilled hole 504. The pipe segment 502 has male threads 506 at one end and female threads 508 at the opposite end. The pipe segment 502 is installed into the formation as a part of a pipe string that is formed by joining pipe segments 502 in an end-to-end configuration in which the male threads 506 of each pipe segment 502 are joined to the female threads 508 of the next pipe segment. Depending on the reservoir, every pipe segment 502 may have a screen assembly 202. In some embodiments, blank joints, which are pipe segments with no screen assembly 202, may be inserted into the pipe string. The orientation of each predrilled hole 504 is then determined by the orientation of the pipe segment 502 when the threads are completely joined to the next pipe segment. Thus, the predrilled holes 504 may be somewhat randomly oriented to the vertical axis of the pipe segment 502, which may lower the flow through the pipe.

FIG. 6 is a drawing of a pipe string 600, showing a build-up of liquid 602 that can result when the holes 604 are not located at the bottom of the pipe string 600. The level 606 of the liquid 602 is controlled by the distance of the holes 604 from the bottom of the vertical axis 608. In this example, the holes 604 are located about half way up from the bottom of the pipe string 600 and, as a result, the lower half of the pipe string 600 is filled with liquid 602, effectively reducing the cross-sectional area available for vapor flow 610 by about 50%. This can result in a substantial pressure drop. FIG. 6 illustrates that liquid 602, or other fluids, can accumulate in the injector wellbore when using a design with a restricted number of holes 604 that are drilled prior to the pipe string 600 being installed, such as is the case with a throttled-flow liner design.

FIG. 7 is a drawing of a pipe string 700, showing complete drainage of condensate when the holes are located at the bottom of the pipe string 700. In an embodiment, the pipe string 700 is installed without pre-drilling holes behind the screen assemblies. After installation, the locations of the screen assemblies 202 can be determined. For example, blast joints 206 that may be integral to each screen assembly 202 can be found using various techniques, as discussed further with respect to FIG. 8. The holes 702 can then be drilled in the pipe string 700 behind the screen assemblies 202, allowing the holes 702 to be drilled substantially downwards with respect to the radial axis 704 of the pipe string 700.

In addition to lowering the amount of liquid that may build up in an injection well, the downward orientation of the holes 702 makes production wells more resistant to the coning of vapor, which causes reproduction of the vapor from the production wells. As the production of steam or other vapors can be a significant operating cost for thermal enhanced oil recovery (EOR) operations, preventing vapor reproduction can improve the project economics.

FIG. 8 is a plot 800 showing the use of gamma ray logging to locate blast joints to allow the positioning of holes. The x-axis 802 represents the distance down the wellbore from the surface location (in meters), while the y-axis 804 represents the intensity 806 of gamma rays received at a detector. As the gamma ray logging is measuring gamma rays emitted by natural sources in the surrounding rock, a lower value can represent a higher density for the surrounding pipe. The gamma logging tool can identify the increased density of the blast joints located above the base pipe. Each of the low points can then be used to identify a location for drilling a hole 808.

In embodiments, any number of other techniques may be used to locate screen assemblies for drilling the holes. For example, a thicker wall section of pipe can be installed at a known offset from each screen assembly for location by the gamma ray logging. Portions of the ring or base pipe itself can be tagged, such as with a radioactive source, allowing the accurate positioning of the tool for drilling each hole. Further, a weak radioactive tag may be directly included at each location, for example, in a blast joint, to accurately locate the tool for the drilling of each hole.

In an embodiment, a profiled section of the base pipe, for example, about 0.5 to 1 cm narrower than the base pipe, may be included in proximity to the planned hole location to locate the tool. Similarly, a profile section may be included in the segment that provides an indentation for an accurately positioning of the tool for the drilling of each hole. To move past the indentation, the tool can be rotated to disengage the indentation and then moved. A segmented ring may be included to function in a similar manner. The segmented ring can engage the tool at one orientation and disengage when the tool is rotated to a different orientation.

Once the locations are determined, specialized drilling tools can be used to drill the required number of holes with the desired locations and orientations. For example, such tools can include the MaxPERF Drilling Tool, available from Penetrators Canada, Inc. of Red Deer, Alberta, Canada. For injection wells, the preferred hole orientation is vertically downward as this can help to ensure that any liquids present, such as condensate, can be easily removed from the pipe string. As discussed previously, if the hole orientation allowed these liquids to accumulate within the liner, the liquids would effectively reduce the hydraulic diameter of the liner, increasing the pressure drop along the injection liner. In some instances, the holes may be slightly offset from the vertical axis at the bottom of the pipe. For example, this may be done in a production well to provide a sump for sand that infiltrates the well bore. Not all of the screen assemblies have to be placed into production at the time of installation as discussed with respect to FIGS. 9(A)-(C).

Sparing Screen Assemblies

FIG. 9(A) is a drawing of five installed screen assemblies 202 placed on a pipe string 900. Spare screen assemblies 202, for example, which are not opened to flow immediately after installation, can be installed during the initial installation of the pipe string 900. Accordingly, if one or more of the initial screen assemblies 202 fail, or if a determination is made to change the distribution of steam or solvent along the pipe string 900, the holes leading to some screen assemblies 202 can be obstructed and holes may be drilled at one or more of the spare screen assemblies 202. As a result, the pipe string 900 can be refurbished at a significantly lower cost than redrilling either the horizontal section or the entire well.

FIG. 9(B) is a drawing of the five installed screen assemblies 202 on the pipe string 900, in which three of the screen assemblies 202, labeled A, C, and E, have been accessed by drilling holes 902. Two remaining screen assemblies 202, B and D have been left closed as spares for futures use. As the field matures, it may be found that some of the screen assemblies 202 have failed, for example, allowing sand to accumulate in the pipe string 900 of a production well or to have become intervals of excess steam communication in an injection well. The screen assemblies 202 involved can be identified by surveying the well for sand accumulations or intervals of reduced sub-cooling.

FIG. 9(C) is a drawing of the series of screen assemblies 202 placed on a pipe segment, showing the plugging of a hole 904 and drilling of a new hole 906. In this example, screen assembly 202C was blocked and a hole 906 was opened behind screen assembly 202B to replace screen assembly 202C. The hole 904 in the failed screen assembly 202C can be obstructed, for example, using a cement squeeze, a scab liner, or any number of other techniques.

In addition to repairing failed screen assemblies 202, as the recovery process matures, it may become valuable to change the openings to screen assemblies 200 along either the injection or production wells. The same techniques described herein can be used to locate and drill additional holes 908 at a desired subset of the open screen assemblies 200. Using these techniques, a well can be effectively repaired and rejuvenated for less cost than it would cost to drill a replacement well.

FIG. 10 is a method of improving the harvesting of hydrocarbons from a reservoir by drillings holes after the well is lined. The method 1000 begins at block 1002 with a mapping of the locations of resources in a reservoir and a plan for harvesting those resources. The mapping can include locating positions for injection wells and production wells, as well as locating initial and subsequent positions for screen assemblies. Generally, the mapping will be performed in the initial planning stages of the recovery scheme. For example, prior to the start of recovery operations, a geologic model can be created for the development area. This geologic model is usually constructed using a geologic modeling software program. Available open hole and cased hole log, core, 2D and 3D seismic data, and knowledge of the depositional environment setting can all be used in the construction the geologic model. The geologic model and knowledge of surface access constraints can then be used to complete the layout of the recovery process wells, e.g., the injection and production wells, and the surface pads.

At block 1004, a series of performance predictions can be made using a reservoir simulation program, such as Computer Modeling Group's STARs program, in order to identify useful locations to open screen assemblies. The simulations can also help identify how the screen assembly locations should be changed, for example, by plugging old screen assemblies or drilling holes at new screen assemblies, as the field matures.

The process needs to consider both the needs of individual well pairs and the overall pattern needs. For example, changes in geology and well design may result in different approaches for different wells within the development. It may also be possible to use simple empirical or analog based models for performance predictions. Further, in many developments, one or more follow-up recovery processes, such as the drilling of in-fill wells, can be used to further enhance the recovery of the hydrocarbons. The options to extend recovery can be considered during the pressure cycling planning phase, in addition to any operating pressure and production rate limitations associated with the installed lift system to be used in the production wells.

At block 1006, the wells, such as SAGD well pairs, used to harvest the hydrocarbon from the reservoir can be drilled. After the well pairs have been drilled, data collected during their drilling as well as data collected during the operation of the recovery process, such as cased hole logs including temperature logs, observation wells, additional time lapse seismic or other remote surveying data, can be used to update the geologic model. This may be used to map the evolution of the depletion patterns as the recovery process matures. The depletion patterns within the reservoir will be influenced by well placement decisions, geological heterogeneity, well failures, and day to day operating decisions. The depletion patterns may determine the optimum locations to open new screen assemblies.

At block 1008, the holes may be drilled behind the screen assemblies that are to be initially opened. At block 1010, hydrocarbon resources can be harvested from the reservoir using the wells. For example, steam, solvent, or combinations of these agents can be injected into the reservoir through the open screen assemblies along the injections wells. Fluids including hydrocarbons, injectants, water, and the like, can be produced from the production well through the open screen assemblies along the production well.

At block 1012, a determination can be made as to whether any screen assemblies have failed. This may also mark the point in production that planned changes in the open or closed screen assemblies can be made. If any screen assemblies have failed or changes are planned, process flow may proceed to block 1014.

At block 1014, any holes into screen assemblies that have failed, or desired to be closed, may be blocked. This may not be needed, if the change is determined to merely be drilling a new hole under a blast joint in the same screen assembly. At block 1016, new holes may be drilled in pipe strings, for example, at locations under new screen assemblies and under currently open screen assemblies that need increases in flow. Process flow can then return to block 1010 to continue production until another screen assembly fails.

While the present techniques may be susceptible to various modifications and alternative forms, the embodiments discussed above have been shown only by way of example. However, it should again be understood that the techniques is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. 

What is claimed is:
 1. A method for improving recovery from a subsurface hydrocarbon reservoir, comprising: drilling a well comprising a horizontal segment through a reservoir interval; installing a pipe string in the horizontal well segment, wherein the pipe string comprises a plurality of screen assemblies; locating each of the plurality of screen assemblies; and drilling a hole in the pipe string at a portion of the plurality of screen assemblies, wherein each hole is drilled at a desired orientation to a radial axis of the drill string.
 2. The method of claim 1, comprising: drilling a plurality of injection wells through the reservoir interval; and drilling a plurality of production wells through the reservoir interval.
 3. The method of claim 1, comprising determining locations for the plurality of screen assemblies from reservoir data.
 4. The method of claim 3, wherein the reservoir data comprises geologic data, seismic data, open hole log data, or any combinations thereof.
 5. The method of claim 1, comprising identifying the portion of the plurality of screen assemblies at which to drill the hole.
 6. The method of claim 1, comprising: identifying a hole that has failed in a screen assembly; plugging the hole; and drilling a new hole.
 7. The method of claim 2, comprising: drilling a first size of hole in each of the plurality of injection wells; and drilling a second size hole in each of the plurality of production wells.
 8. The method of claim 1, comprising increasing a flow area in the pipe string at a screen assembly.
 9. The method of claim 8, comprising drilling additional holes at a screen assembly.
 10. The method of claim 1, comprising locating the screen assembly using a gamma ray tool.
 11. The method of claim 1, comprising locating the screen assembly using a density detector.
 12. The method of claim 1, comprising locating the screen assembly using a profile segment of pipe installed at a known location in a pipestring.
 13. The method of claim 1, comprising orienting the drilled holes vertically downward.
 14. The method of claim 1, comprising orienting the drilled holes within about 20° of vertically downward.
 15. The method of claim 1, comprising drilling a hole in at least one of the plurality of screen assemblies after production has commenced.
 16. The method of claim 1, comprising plugging a hole by squeezing cement into the hole.
 17. The method of claim 1, comprising plugging a hole using a low profile casing patch.
 18. The method of claim 1, comprising plugging a hole using a scab liner.
 19. A system for improving the recovery of resources from a reservoir, comprising: a reservoir; a horizontal well drilled through the reservoir, wherein the horizontal well comprises a plurality of pipe joints that have a screen assembly mounted thereon; a detection apparatus configured to locate a screen assembly on a pipe joint; and a drilling device configured to drill a hole in a pipe joint at a selected orientation to the vertical.
 20. The system of claim 19, comprising two horizontal wells, wherein one horizontal is an injection well and a second horizontal well is a production well.
 21. The system of claim 19, wherein a portion of the plurality of pipe joints that have a screen assembly have a hole drilled in the pipe joint underneath the screen assembly.
 22. A method for harvesting hydrocarbons from an oil sands reservoir, comprising: drilling a steam assisted gravity drainage (SAGD) well pair through the oil sands reservoir; placing a pipe string in each of the wells of the SAGD well pair, wherein the pipe string comprises a plurality of screen assemblies, and wherein the pipe string has no holes prior to placement; selecting a portion of the screen assemblies at which to drill holes in a base pipe underneath the screen assembly; drilling the holes at a selected orientation to the radial axis of the base pipe; injecting steam into an injection well in the SAGD well pair; and producing fluids from a production well in the SAGD well pair.
 23. The method of claim 22, comprising: identifying a screen assembly that has failed; determining the reason for the failure; if the failure is due to a hole failing: drilling a new hole under the screen assembly; and, if the failure is due to the screen assembly failing: plugging the hole under the screen assembly; and drilling a new hole under a new screen assembly. 